Methods of using treatment fluids and, more particularly, methods of using treatment fluids in the form of an invert emulsion comprising a fluorous oil external phase, a salt-free non-chloride containing internal phase, and a fluorous-based surfactant in well operations may be provided.
Treatment fluid may be used in a variety of well operations. Examples of treatment fluids include drilling fluids, packer fluids, displacement fluids, completion fluids, work-over fluids etc. Drilling fluids may be used to maintain hydrostatic pressure in the wellbore, prevent formation damage, suspend cuttings, and to transport cuttings to the surface. Drilling fluids may be water-based or oil-based. Typical water-based drilling fluids may be composed of solely water or a mixture of water and various types of clay. Oil based drilling fluids may use a base fluid of a petroleum product.
Packer fluids may be used during drilling and/or completion and may serve a variety of functions. Generally, they are placed above a packer and may be used to provide hydrostatic pressure, prevent collapse of the wellbore, prevent heat transfer, protect wellbore components as well as any metals and elastomers from corrosion, and be of a sufficient density to control the producing formation. Typical packer fluids may be solids-free and resistant to changes in their viscosity.
Fluid displacement utilizes one or more fluids to displace another fluid from the wellbore. Typically this may be done to prevent contamination of one fluid with another or the contamination of one fluid with the formation. A displacement fluid or as it is also known, a spacer fluid, may be water-based fluids. In most instances, spacer fluids may be used to separate drilling fluid from a cement composition during a cementing operation. Because the spacer fluid will be used to separate two other fluids, such as the drilling fluid and the cement composition, the spacer fluid should be compatible with both treatment fluids.
Treatment fluids for some well applications may comprise brines. Problems with brines may include high thermal conductivity and the potential for corrosion of well components. Additionally, using treatment fluids of different formulations may create incompatibility issues. Switching between treatment fluids in a subterranean operation may be costly in both time and resources. Varied fluid types may require separate fluid storage, additional manpower, and additional equipment. In addition to the increased operating expenses, varied fluid use may create additional worksite problems such as higher environmental burdens, fluid incompatibilities, and the inability to reuse fluids and materials once their respective portion of the operation has been completed.